Much of the natural gas used in the United States is produced along the Gulf Coast. There is an extensive pipeline network both offshore and onshore that transports this natural gas from the wellhead to market. In other parts of the world, there is also natural gas production, but sometimes there is no pipeline network to transport the gas to market. In the industry, this sort of natural gas is often referred to as “stranded” because there is no ready market or pipeline connection. As a result, this stranded gas that is produced concurrently with crude oil is often burned at a flare. This is sometimes referred to as being “flared off.”
Different business concepts have been developed to more effectively utilize stranded gas. One such concept is construction of a petrochemical plant near the source of natural gas to use the gas as a feedstock for the plant. Several ammonia and urea plants have been constructed around the world for this purpose.
Another approach is to liquefy the natural gas at or near the source and to transport the LNG via ship to a receiving terminal. At the LNG receiving facility, the LNG is offloaded from the transport ship and stored in cryogenic tanks located onshore. At some point, the LNG is transferred from the cryogenic storage tanks to a conventional vaporizer system and gasified. The gas is then sent to market via a pipeline. At the start of this process, liquefaction may consume 9–10% of the LNG by volume. At the end of the process, the gasification may consume an additional 2–3% of the LNG by volume. To the best of Applicants knowledge, none of the existing conventional LNG facilities that use vaporizer systems thereafter store the resulting gas in salt caverns. Rather, the conventional LNG facilities with vaporizers transfer all of the resulting gas to a pipeline for transmission to market.
Currently there are more than 100 LNG transport ships in service worldwide and more are on order. LNG transport ships are specifically designed to transport the LNG as a cryogenic liquid at or below −250° F. and near or slightly above atmospheric pressure. Further, the ships run on the LNG and are counter-flooded to maintain a constant draft of about 40 feet. The LNG ships currently in service vary in size and capacity, but some hold about 3 billion cubic feet of gas (Bcf) (approx. 840,000 barrels) or more. Some of the ships of the future may have even greater capacity and as much as 5 Bcf. One of the reasons LNG is transported as a liquid is because it takes less space.
There are a number of LNG facilities around the world. In the U.S., two LNG receiving facilities are currently operational (one located in Everett, Mass. and one located south of Lake Charles, La.) and two are being refurbished (one located in Cove Point, Md. and one located at Elba Island, Ga.). Construction of additional LNG facilities in the U.S. has been announced by several different concerns.
The LNG receiving facilities in the U.S. typically include offloading pumps and equipment, cryogenic storage tanks and a conventional vaporizer system to convert the LNG into a gas. The gas may be odorized using conventional equipment before it is transmitted to market via a pipeline. LNG terminals are typically designed for peak shaving or as a base load facility. Base load LNG vaporization is the term applied to a system that requires almost constant vaporization of LNG for the basic load rather than periodic vaporization for seasonal or peak incremental requirements for a natural gas distribution system. At a typical base load LNG facility, a LNG ship will arrive every 3–5 days to offload the LNG. The LNG is pumped from the ship to the LNG storage tank(s) as a liquid (approx. −250° F.) and stored as a liquid at low-pressure (about one atmosphere). It typically may take 12 hours or more to pump the LNG from the ship to the cryogenic storage tanks onshore.
LNG transport ships may cost more than $100,000,000 to build. It is therefore expedient to offload the LNG as quickly as possible so the ship can return to sea and pick up another load. A typical U.S. LNG base load facility will have three or four cryogenic storage tanks with capacities that vary, but are in the range of 250,000–400,000 barrels each. Many of the current LNG ships have a capacity of approximately 840,000 barrels. It therefore will take several cryogenic tanks to hold the entire cargo from one LNG ship. These tanks are not available to receive LNG from another ship until they are again mostly emptied.
Conventional base load LNG terminals are continuously vaporizing the LNG from the cryogenic tanks and pumping it into a pipeline for transport to market. So, during the interval between ships (3–5 days), the facility converts the LNG to gas (referred to as regasification, gasification or vaporization) which empties the cryogenic tanks to make room for the next shipment. The LNG receiving and gasification terminal may produce in excess of a billion cubic feet of gas per day (BCFD). In summary, transport ships may arrive every few days, but vaporization of the LNG at a base load facility is generally continuous. Conventional vaporizer systems, well known to those skilled in the art, are used to warm and convert the LNG to usable gas. The LNG is warmed from approximately −250° F. in the vaporizer system and converted from liquid phase to usable gas before it can be transferred to a pipeline. Unfortunately, some of the gas is used as a heat source in the vaporization process, or if ambient temperature fluids are used, very large heat exchangers are required. There is a need for a more economical way to convert the LNG from a cold liquid to usable gas.
LNG cryogenic storage tanks are expensive to build and maintain. Further, the cryogenic tanks are on the surface and present a tempting terrorist target. There is therefore a need for a new way to receive and store LNG for both base load and peak shaving facilities. Specifically, there is a need to develop a new methodology that eliminates the need for the expensive cryogenic storage tanks. More importantly, there is a need for a more secure way to store huge amounts of flammable materials.
There are many different types of salt formations around the world. Some, but not all of these salt formations are suitable for cavern storage of hydrocarbons. For example, “domal” type salt is usually suitable for cavern storage. In the U.S., there are more than 300 known salt domes, many of which are located in offshore territorial waters. Salt domes are also known to exist in other areas of the world including Mexico, Northeast Brazil and Europe. Salt domes are solid formations of salt that may have a core temperature of 90° F. or more. A well can be drilled into the salt dome and fresh water can be injected through the well into the salt to create a cavern. Salt cavern storage of hydrocarbons is a proven technique that is well established in the oil and gas industry. Salt caverns are capable of storing large quantities of fluid. Salt caverns have high sendout capacity and most important, they are very, very secure. For example, the U.S. Strategic Petroleum Reserve now stores approximately 600,000,000 barrels of crude oil in salt caverns in Louisiana and Texas, i.e., at Bryan Mound, Tex.
When fresh water is injected into domal salt, it dissolves thus creating brine, which is returned to the surface. The more fresh water that is injected into the salt dome, the larger the cavern becomes. The tops of many salt domes are often found at depths of less than 1500 feet. A salt cavern is an elongate chamber that may be up to 1,500 feet in length and have a capacity that varies between 3–15,000,000 barrels. The largest is about 40 million barrels. Each cavern itself needs to be fully surrounded by the salt formation so nothing escapes to the surrounding strata or another cavern. Multiple caverns will typically be formed in a single salt dome. Presently, there are more than a 1,000 salt caverns being used in the U.S. and Canada to store hydrocarbons including the aforementioned crude oil stored in the Strategic Petroleum Reserve. Sixty or more of these salt caverns are being used to store natural gas.
Two different conventional techniques are used in salt cavern storage-compensated and uncompensated. In a compensated cavern, brine or water is pumped into the bottom of the salt cavern to displace the hydrocarbon or other product out of the cavern. The product floats on top of the brine. When product is injected into the cavern, the brine is forced out. Hydrocarbons do not mix with the brine making it an ideal fluid to use in a compensated salt cavern. In an uncompensated storage cavern, no displacing liquid is used. Uncompensated salt caverns are commonly used to store natural gas that has been produced from wells. High-pressure compressors are used to inject the natural gas in an uncompensated salt cavern. Some natural gas must always be left in the cavern to prevent cavern closure due to salt creep. The volume of gas that must always be left in an uncompensated cavern is sometimes referred to in the industry as a “cushion.” This gas provides a minimum storage pressure that must be maintained in the cavern. Again, to the best of Applicants knowledge, none of the present LNG receiving facilities take the LNG from the tankers, vaporize it and then store the resulting gas in salt caverns.
Uncompensated salt caverns for natural gas storage preferably operate in a temperature range of approximately +40° F. to +140° F. and pressures of 1500 to 4000 psig. If a cryogenic fluid at sub-zero temperature is pumped into a cavern, thermal fracturing of the salt may occur and degrade the integrity of the salt cavern. For this reason, LNG at very low temperatures cannot be stored in conventional salt caverns. If a fluid is pumped into a salt cavern and the fluid is above 140° F. it will encourage creep and decrease the volume of the salt cavern.
U.S. Pat. No. 5,511,905 is owned by the assignee of the present application. William M. Bishop is listed as a joint inventor on the present application and the '905 patent. This prior art patent discloses warming of LNG with brine (at approximately 90° F.) using a heat exchanger in a compensated salt cavern. This prior patent teaches storage in the dense phase in the compensated salt cavern. The '905 Patent does not disclose use of an uncompensated salt cavern. The '905 Patent also discloses that cold fluids may be warmed using a heat exchanger at the surface. The surface heat exchanger might be used where the cold fluids being offloaded from a tanker are to be heated for transportation through a pipeline. The brine passing through the surface heat exchanger could be pumped from a brine pond rather than the subterranean cavern.
U.S. Pat. No. 6,298,671 is owned by BP Amoco Corporation and is for a Method for Producing, Transporting, Offloading, Storing and Distributing Natural Gas to a Marketplace. The patent teaches production of natural gas from a first remotely located subterranean formation, which is a natural gas producing field. The natural gas is liquefied and shipped to another location. The LNG is re-gasified and injected into a second subterranean formation capable of storing natural gas which is a depleted or at least a partially depleted subterranean formation which has previously produced gas in sufficient quantities to justify the construction of a system of producing wells, gathering facilities and distribution pipelines for the distribution to a market of natural gas from the subterranean formation. The patent teaches injection of the re-gasified natural gas into the depleted or partially depleted natural gas field at temperatures above the hydrate formation level from 32° F. to about 80° F. and at pressures of from about 200 to about 2500 psig. This patent makes no mention of a salt cavern. This patent makes no mention of dense phase or the importance thereof. Furthermore, there are limitations on the injection and send out capacity of depleted and partially depleted gas reservoirs that are not present in salt cavern storage. In addition, temperature variances between the depleted reservoir and the injected gas create problems in the depleted reservoir itself that are not present in salt cavern storage. For all of these many reasons, salt caverns are preferred over cryogenic storage tanks or depleted gas reservoirs for use in a modern LNG facility.
Salt cavern natural gas storage is known and utilized between natural gas production facilities and natural gas markets to provide a buffer to swings in supply of natural gas and to swings in demand for natural gas. Swings in supply from gas production wells can be caused by weather phenomenon such as freezes or hurricanes or in the normal maintenance associated with natural gas production facilities. Swings in natural gas demand can be weather related such as demand for heating in cold weather or in demand for electricity generated from natural gas fueled generators. Salt cavern storage of natural gas is widely known as an excellent technology to accommodate very large demand increases in natural gas because of the ability of caverns to deliver large amounts of natural gas to pipelines on very short notice. The U.S. on average consumes about 60 billion cubic feet per day (Bcf/D) of natural gas but in peak demand periods can consume in excess of 115 Bcf/D. Natural gas storage is used to accommodate that wide variation in demand. There is over 3 trillion cubic feet (TCF) of natural gas storage capacity in the US of which about 95% is storage of natural gas in depleted reservoirs and aquifers and the remaining 5% in salt caverns. While salt caverns make up only about 5% of the storage capacity they provide more than 14% of the delivery capacity illustrating that salt caverns have much higher deliverability than other forms of storage. Salt caverns are characterized as having very high deliverability instantaneously available to be delivered to the pipeline grid.
The U.S. has the most comprehensive energy infrastructure in the world. The U.S. is the largest energy consuming nation in the world and there are projections that the demand for natural gas and the swings in that demand will increase in the future. There is an extensive pipeline network both offshore and onshore that transports this natural gas from the wellhead to market. Much of the natural gas used in the United States is produced along the Gulf Coast, where there is an abundance of natural gas pipeline distribution networks in proximity to navigable waters. An abundance of natural gas pipeline networks is sometimes referred to as the natural gas infrastructure.
Currently the U.S. consumes more natural gas than it produces. The shortfall in supply is largely made up by pipeline imports from Canada. Only about 1% of the current U.S. natural gas demand is supplied by imported LNG. However there are projections by the Energy Information Agency of the U.S. Department of Energy that in the future imported LNG could supply as much as 6% of demand. Some gas industry projections are that imported LNG could grow to supply more than 10% of demand.
Salt caverns are used to store natural gas that has been produced from wells and transported to the salt caverns via pipelines. Salt cavern storage of natural gas sourced from pipelines is well known to those skilled in the art. Generally pipelines operate at pressures lower than the maximum operating pressures of salt caverns therefore high-pressure compressors are used to boost the pressure from the pipelines and inject the natural gas in to salt caverns. Salt caverns for natural gas storage are preferably operated in a temperature range of approximately +40° F. to +140° F. and pressures from about 1500 to about 4000 psig. Salt has varying degrees of plasticity depending primarily upon temperature and pressure. The hot discharge from natural gas compressors is commonly cooled prior to injection into salt caverns to temperatures below +140° F. to reduce salt movement or “creep.” Salt caverns store natural gas at pressures exceeding the operating pressures of the pipelines to which they are connected so the general method of delivery from the caverns to the pipelines is by the positive pressure differential from the cavern to the pipelines. In periods of high natural gas demand salt cavern storage facilities are depleted rapidly and generally the storage inventories are not replenished until periods of low natural gas demand. The practice in the industry of filling a salt cavern storage facility and then redelivering the inventory to a natural gas pipeline network is called a turnaround or turn. The number of turns a facility can perform during a period of time is a measure of its utilization. In periods of continued high demand for natural gas such as in a prolonged cold wave there may be an inability to refill the salt cavern storage facility because of the general inability of the U.S. domestic production of natural gas to match the high rates of natural gas consumption. In general natural gas production from production wells is at a relatively steady rate while consumption of natural gas in the U.S. is highly variable and subject to significant peaks and valleys. Salt cavern storage facilities are recognized as an excellent way to fill the gaps in supply and demand on a quick response basis. The trend in the U.S. to build more gas fueled electrical generating facilities will exacerbate the swings in demand since a gas fueled generation plant is characterized by the ability to rapidly shift its output which could increase its fuel requirement as much as 50% in a short time period.
In the U.S. there are more than 60 salt caverns utilized for storing natural gas sourced from pipelines. To the best of the Applicant's knowledge, none of the existing salt caverns used for natural gas storage are also used for the receipt and storage of natural gas sourced from LNG.